Detection of seismic signals using fiber optic distributed sensors

ABSTRACT

A fiber optic distributed vibration system for detecting seismic signals in an earth formation is provided. The system includes a fiber optic cable deployed in a borehole that extends into the earth formation and which is configured to react along its length to a seismic wave incident on the fiber optic cable from outside the borehole. An optical source launches an optical signal into the fiber optic cable while the seismic wave is incident thereon. A receiver detects coherent Rayleigh noise (CRN) produced in response to the optical signal. A processing circuit processes the detected CRN signal to determine characteristics of the earth formation.

TECHNICAL FIELD

The present invention relates generally to borehole seismic surveyingand, more particularly, to detection of seismic events using fiber opticdistributed sensors.

BACKGROUND

Borehole seismic surveys have become among the most versatile ofdownhole measurements used in the hydrocarbon industry. Originally,borehole seismic surveys were limited to correlating time-based surfaceseismic images with depth-based well logs and depth-based reservoirmodels for the purpose of making drilling decisions. Today, however,modern borehole seismic applications extend beyond simple time-depthcorrelations to generate a wide variety of useful information aboutreservoir extent, geometry and heterogeneity, as well as fluid contentand pore-pressure, rock mechanical properties, enhanced oil-recoveryprogress, elastic anisotropy parameters, induced fractures geometry andnatural fracture orientation and intensity. More recently, boreholeseismic measurements have extended beyond applications in thehydrocarbon industry to now include applications in the hydrology andsubterranean carbon sequestration industries.

Regardless of the application, deployment of seismic survey tools inboreholes has been constrained by cost and physical size considerations.For instance, in the hydrocarbon production industry, borehole seismicsurvey tools typically have a diameter of two or more inches and, thus,may not be deployed in a borehole if either a drillstring or tubing isin place (unless detectors are placed on the drillstring before drillingis commenced). As a result, the performance of a borehole seismic surveygenerally entails pulling the drillstring or production tubing (if oneor the other is in place), running in an array of survey tools,conducting the survey, pulling the tool array, and then replacing thedrillstring or tubing (if needed). As a result, the seismic survey iscostly, both in terms of rig time and, in some instances, lostproduction while the survey is being performed. In addition, boreholesurvey tools typically include both downhole sensors and electronics.The harsh downhole environment increases the complexity and cost of thesensors and electronics since they must be designed to withstandelevated temperatures and pressures for extended periods of time.Consequently, seismic survey tools generally are not considereddisposable and may not be either abandoned in the borehole after use orleft inactive in a borehole for extended periods (such as for time-lapsesurveys) due to lost revenues that could be obtained by deploying thesurvey tools in other locations.

BRIEF DESCRIPTION OF THE DRAWINGS

Certain embodiments of the invention will hereafter be described withreference to the accompanying drawings, wherein like reference numeralsdenote like elements. It should be understood, however, that theaccompanying drawings illustrate only the various implementationsdescribed herein and are not meant to limit the scope of varioustechnologies described herein. The drawings are as follows:

FIG. 1 is a transverse cross-section of a borehole illustratingexemplary deployment locations of fiber optic sensors, in accordancewith an embodiment of the invention.

FIG. 2 shows an exemplary installation of a fiber optic vibration sensorin a borehole to monitor microseismic signals propagating through aformation, in accordance with an embodiment of the invention.

FIG. 3 shows exemplary radiation patterns of compressional and shearenergy emitted during a microseismic event in an earth formation.

FIG. 4 shows another exemplary installation of a fiber optic vibrationsensor in a borehole to monitor seismic signals propagating through aformation, in accordance with an embodiment of the invention.

FIG. 5 shows yet another exemplary installation of multiple fiber opticvibration sensors in a borehole to monitor seismic signals propagatingthrough a formation from a source in another borehole, in accordancewith an embodiment of the invention.

FIG. 6 show an exemplary interrogation and data acquisition system toacquire information form a fiber optic vibration sensor deployed in aborehole to monitor microseismic events, in accordance with anembodiment of the invention.

FIG. 7 is an exemplary distributed fiber optic vibration sensorincluding a plurality of discrete sensors, in accordance with anembodiment of the invention.

DETAILED DESCRIPTION

In the following description, numerous details are set forth to providean understanding of the present invention. However, it will beunderstood by those skilled in the art that the present invention may bepracticed without these details and that numerous variations ormodifications from the described embodiments may be possible.

In the specification and appended claims: the terms “connect”,“connection”, “connected”, “in connection with”, and “connecting” areused to mean “in direct connection with” or “in connection with viaanother element”; and the term “set” is used to mean “one element” or“more than one element”. As used herein, the terms “up” and “down”,“upper” and “lower”, “upwardly” and downwardly”, “upstream” and“downstream”; “above” and “below”; and other like terms indicatingrelative positions above or below a given point or element are used inthis description to more clearly describe some embodiments of theinvention.

In general, borehole seismic surveys are performed by recording seismicsignals using a single sensor or an array of sensors located in aborehole that extends from the earth surface into a sub-surfaceformation. Depending on the particular application, seismic signals maybe generated by one or more seismic sources located on the earthsurface, in the borehole in which the seismic signals are detected, inan adjacent borehole, and/or in the formation surrounding the borehole.A wide variety of seismic sources may be used to generate the seismicsignals. For instance, surface seismic sources may include air-guns,accelerated weight drops, vibrator trucks, and explosives. Commondownhole seismic sources may include piezoelectric pulsers, orbital-,vertical- and radial-vibrators, hammers, air-guns, sparkers, implosivecanisters, and explosives. In some cases, such as in microseismic orhydrofracturing monitoring applications, the seismic signals are emittedeither when fractures are generated in the surrounding formation or whenthe rock on either side of existing fractures slip relative to oneanother. Depending on the particular application in which the monitoringis being performed, the seismic source may be located at a singlelocation, a limited number of locations (e.g., arranged in a single linealong the borehole or over the ground surface), or in multiple locationsso as to substantially cover the entire surface of the earth in thevicinity of the borehole in which the sensors are detecting the seismicsignals (e.g., arranged in multiple parallel lines, in multiple linesradiating outward from a single location, in a spiral, or in a random orpseudo-random manner).

The seismic energy generated as a result of the seismic source may berecorded by any of a variety of types of seismic sensors, such ashydrophones, geophones, accelerometers, or a combination thereof. Intypical downhole applications, these types of sensors are coupled toelectrical components downhole which amplify, condition (e.g., bandpass) and digitize the electrical signals generated by the sensors inresponse to detection of a seismic event. The digitized signals may thenbe transmitted (e.g., via electrical wireline, mud pulse telemetry,fiber optic cable, etc.) to the surface where they are recorded, or theymay be temporarily stored in a downhole storage device, such as asolid-state memory, and then later retrieved. In either configuration,the need for downhole electronics adds to the physical size, cost andcomplexity of the survey tool, particularly since the electronics mustbe able to withstand, or be protected from, elevated temperatures andpressures of the downhole environment for extended periods of time.

These constraints, when combined with limitations on the amount of powerthat can be delivered downhole and the amount of data that can either bestored downhole or transmitted to the surface, have also served torestrict the number of sensors that may be used in a seismic surveyinstallation. For instance, in the past, borehole seismic survey systemshave been constrained to the use of one, five or eight sensors. And,despite modern technological advances, more recent installationstypically can deploy no more than one hundred sensors.

The size constraint also is a serious limitation since the seismic toolis deployed in a confined location (i.e., in a borehole). For instance,current downhole survey tools typically have a diameter of two or moreinches. This size limits the manner in which the survey tool may bedeployed since its relatively large diameter may preclude running thetool either with a drillstring or inside the production tubing (if oneis installed) or in the annulus between the casing and the tubing ordrillstring. As a result, either the drillstring or production tubingoften must be removed from the borehole before the seismic survey toolmay be introduced and the survey conducted. Since removal of tubing ordrillstring is a time consuming and costly procedure, performing asurvey in this manner is not particularly desirable. Furthermore,abandoning the survey tool in the borehole also is almost never a viableoption since the survey tool itself often is quite expensive and thus isnot considered to be a disposable item and its presence in the boreholeafter abandonment may impede further operation of the well. Yet further,leaving the tool in an inactive state in the borehole to performtime-lapse seismic surveys, for instance, also is not an attractiveoption due to the loss of revenue that could otherwise be realized byusing the tool for surveys in other downhole locations.

Accordingly, in accordance with embodiments of the invention, seismicsignals (including microseismic signals) propagating through an earthformation outside a borehole are detected using one or more fiber opticdistributed vibration sensors located in the borehole. The smalldiameter of the optical fiber (e.g., ¼ inch or less) allows fordeployment of the fiber optic distributed sensor either inside or behindproduction tubing or the drillstring, thus eliminating the need toeither shut in the well and/or pull tubing or a drillstring beforeconducting a seismic survey. Further, an optical fiber seismic signaldetection system does not require costly downhole electronics. Instead,the electronics for acquiring seismic data from the fiber optic sensorall may be located on the surface. Thus, only the relatively inexpensivefiber optic sensor itself is deployed downhole and, due to its non-toxicnature, may be abandoned or left inactive in the borehole after use.

Generally, to monitor seismic signals using a fiber optic distributedvibration sensor, optical pulses are launched into the fiber opticsensor and reflected or scattered light generated in response to thepulses is detected over an extended period of time. The scattered lightthat is generated while seismic waves originating outside the boreholeare incident along the length of the fiber optic distributed sensor mayprovide information about characteristics of the formation surroundingthe borehole, including changes in these characteristics over a periodof time. Such characteristics may include reservoir extent, geometry andheterogeneity, as well as fluid content and pore pressure, rockmechanical properties, enhanced oil-recovery progress, CO₂ sequestrationprogress, elastic anisotropy parameters, induced fractures geometry andnatural fracture orientation and intensity. In some embodiments, thefiber optic distributed sensor is removably coupled to surfaceelectronics for interrogating and acquiring microseismic event datadetected by the fiber optic distributed sensor. In this manner, one ormore fiber optic distributed sensors may be permanently deployed in theborehole and the surface electronics moved to perform seismic signaldetection using fiber optic distributed sensors installed in otherlocations.

In some embodiments, multiple identical optical fibers may be deployedin the borehole. In such embodiments, the optical fibers may be locatedat different positions within a transverse cross-section of in theborehole for the purpose of detecting the change in phase of the seismicwave as it crosses the borehole and, thus, to determine parametersrelating to the wave's direction of propagation. Alternatively, multipleoptical fibers may be deployed that differ in their construction, suchas being made of differing materials, having different cross-sections,or having different coatings. Due to the differences in construction,the optical fibers may be sensitive to different combinations ofpressure, velocity, acceleration, and/or strain. As a result, themeasurements recorded from co-located positions along the length ofthese multiple fibers may be used to separate the values of thepressure, velocity, acceleration, and/or strain at each co-locatedposition and, thus, to provide more detailed information regarding thecharacteristics and features of the surrounding formation.

In any of the embodiments described above, the one or more fiber opticdistributed sensors may be located in either a simple open or casedborehole. Alternatively, the fiber optic distributed sensors may belocated in the cement outside the borehole casing; inside a control linethat is deployed in the borehole either outside the casing or attachedto the inside of the casing; in the annulus between a production tubingand the casing; attached to the outside of the production tubing; insidea control line that is located in the annulus between the productiontubing and the casing and which may be attached to the outside of theproduction tubing; within the production tubing or coil tubing; withinthe annulus between the production or coil tubing and the casing; or acombination of any of the foregoing locations.

Exemplary deployment locations are illustrated in FIG. 1, whichgenerally depicts a transverse cross-sectional view of a cemented andcased borehole 100 that has been formed in a surrounding formation 102.As shown in FIG. 1, the borehole 100 includes a cement portion 104 and acasing 106. A production tubing 108 is deployed in the borehole suchthat an annulus 110 is formed between the outside wall of the productiontubing 108 and the casing 106. The fiber optic distributed sensorsdeployed in the borehole 100 may be either bare or encased along theirlength in a protective coating or jacket. Yet further, the optical fibermay include a coating or may be encased in a compliant material that isparticularly sensitive to pressure, such as a metallized foam materialor an acoustic-matching medium (e.g., a gel), to thereby enhance thesensitivity of the seismic measurement. The pressure-sensitive coatingor material may be disposed uniformly along the length of the opticalfiber or may be disposed at select locations along the length. Stillfurther, a bare, coated or encased fiber may be installed inside acontrol line or other thin-walled tubing.

As examples, and with reference to FIG. 1, fiber 112 is located in thecement 104, while fiber 114 is located in a control line 116 attached tothe outside of the casing 106. Fibers 118, 120, and 122 are located inthe annulus 110 between the tubing 108 and the casing 106, with fiber118 being attached to the inside of the casing 106 and the fiber 120being attached to the outside of the tubing 108. Fibers 124, 126, and128 are located inside of control lines 130, 132, and 134, respectively,with control line 130 being coupled to the inside of the casing 106 andcontrol line 132 being coupled to the outside of the tubing 108. Fiber136 is deployed in the production tubing 108, while fiber 138 isinstalled in a control line 140 that is deployed in the tubing 108.Finally, fibers 142 and 144 are both installed within a single controlline 146 that is deployed in the annulus 110. It should that understoodthat the various deployment locations are provided as examples only andthe other, fewer, or more locations may be used, including a singlelocation or various other combinations of locations for multiple fibers.

In embodiments in which the optical fiber cable or the control line isattached to either the inside or outside of a structure (e.g., tubing,casing, etc.), the attachment may be implemented in various manners,such as magnetically, with some form of adhesive, or by cementing thefiber in place. Alternatively, in some embodiments, the optical fibermay be disposed within a helical control line which is deployed in theborehole under extension and then released so that spring forces fromthe helical configuration clamp the control line against the casing orborehole wall. Attaching the optical fiber or control line to the casingor the formation may serve to provide for better (i.e., stronger)detection of the seismic signals, although the other types of deployment(e.g., loosely deployed within a control line, in the annulus, in thetubing) also provide for a sufficient transfer function to detectseismic events.

In any of the embodiments described herein, the optical fiber may beeither a single-mode fiber or a multi-mode fiber, depending on theparticular application as well as on the particular interrogation andacquisition equipment used to collect data from the fiber optic sensor.

The fiber optic distributed sensors shown in FIG. 1 may be deployedwithin the borehole 100 using known methods for conveying cables intowellbores, such as a control line containing an optical fiber cable, ora coil tubing containing an optical fiber cable, or a wireline cablewith integrated optical fibers, among other methods. With respect to thefiber optic distributed sensor 112 which is deployed behind the casing106 of the borehole 100, the fiber optic cable may be deployed with (andpossibly attached to) the casing 106 as it is lowered into the borehole100. The casing 106 may be cemented in place when the gap between theborehole 100 and the casing 106 is filled with cement 104. Inembodiments in which the borehole 100 is cased with casing 106 andcompleted with a production tubing 108, intervention-type deploymentmethods may be employed to deploy any of the distributed sensors 136,138 within the production tubing 108.

Regardless of the deployment location and technique used, seismicsignals (generated during a seismic survey, for instance) may bedetected by any one or more of the fiber optic distributed sensors shownin FIG. 1. As an example, any of the following types of seismic surveysmay be performed with one or more fiber optic distributed vibrationsensors being used in place of traditional receiver arrays:

-   -   Checkshot: used to tie time-based surface seismic and        depth-based logs; characterized by a single source location        above a sparse spacing of receiver locations, typically in        vertical wells.    -   Salt-Proximity Surveys: used to locate the position of a salt        face or body with respect to the well; characterized by one (or        a small number) of wells offset from the position vertically        above the receiver array, and generally above the salt body; the        high salt-sediment velocity contrast is utilized to invert the        data.    -   Zero-Offset Vertical Seismic Profile (VSP): used for a more        sophisticated tie between time-based surface seismic and        depth-based logs and an image of reflectors above and below the        depth of the deepest sensor; characterized by a single source        location above a dense spacing (every 50-100 feet) of receiver        depths typically in a vertical well.    -   Walkabove VSP: an extension of the Zero-Offset VSP to deviated        to horizontal wells; characterized by a source moved so as to be        located above each of the receiver locations in turn.    -   Offset VSP: used for imaging around and below the receiver array        to detect, for example, faults of dip of subterranean        formations; characterized by a single source location at a        substantial horizontal displacement from a relatively sparse        receiver array.    -   Multi-Offset VSP: an offset VSP expanded to include a small        number of source locations.    -   Walkaway VSP: a further generalization of Multi-Offset VSP to        include a dense array of source locations arranged in a line        usually extending either side of a point directly above the        source array; common uses are to study anisotropy, to calibrate        amplitude variation with source-receiver offset data from        surface seismic surveys and to illuminate larger subterranean        volumes.    -   Walk-Around VSP: typically used for studying anisotropy and the        orientation of naturally occurring fractures; characterized by a        sparse array of sources on the surface arranged in a circles or        arc of a circle centered approximately above a point vertically        above the receiver array.    -   MultiAzimuth Walkaway VSP: a generalization of Walkaway VSP to        include multiple lines of sources with each line at some angle        to the others; typically the lines cross at a point above the        location of the receiver array; commonly used to study seismic        anisotropy effects and the distribution of natural fractures.    -   3DVSP: typically used to image three-dimensional volumes of the        earth above, around and below the receiver array; characterized        by a dense distribution of source locations covering a        substantial area of the earth surface above the receivers; the        distribution of source locations may be in the form of a grid of        parallel lines, a spiral, or a random or pseudo-random pattern,        either deliberately designed or dictated by access restrictions,        for example, along pre-existing roads.    -   Crosswell Seismic: typically used for high-definition imaging of        the space between two or a multitude of boreholes; characterized        by the source being located in one borehole and the receiver        array located in another borehole.    -   Hydrofacture Monitoring (HFM): typically used to locate the        places in which the rock is splitting, or motion is occurring        along existing faults and fractures during the process of        hydrofracturing a well; currently this survey is characterized        by a small number (typically eight) of receivers in one or more        offset boreholes; however, monitoring also may be performed in        the well being hydrofractured.    -   Microseismic Monitoring: similar to hydrofracture monitoring,        but now the seismic events are caused by fluid motions and        stress changes due to production and injection activities;        characterized by the need for long-term deployment of receivers        in one or more boreholes.    -   Time-Lapse Borehole Seismic: all of the borehole seismic surveys        described above (with the exception of HFM and Microseismic        Monitoring which are inherently concerned with dynamic        processes) can be repeated after periods of years, months,        weeks, days, or in some cases hours, to track changes in the        fluid content or stress-state of the reservoir; collectively        these surveys can be referred to as Time-Lapse Borehole Seismic        surveys.

It should be understood that the foregoing surveys are provided asexamples only and that the techniques and seismic monitoring systemsdescribed herein may be used to monitor seismic signals generated inother scenarios, both stimulated and naturally occurring.

As one example, FIG. 2 illustrates an exemplary embodiment of fiberoptic distributed sensors 150/151 and 155/157 deployed in boreholes 152and 153, respectively, to monitor a hydrofracturing stimulation processthat generates fractures in the surrounding earth formation 154. Here,the seismic wave incident on the fiber optic distributed sensors 150,151, 155 and 157 from outside the boreholes 152 and 153 is detected inorder to determine the nature, location and amount of fracturing. Moreparticularly, in the field of seismology, seismic radiation caused byfault motion is described by a moment tensor. As is known in the art,the process of determining the nature and amount of fault deformationfrom acquired seismic data is referred to as moment tensor inversion. Toinvert the moment tensor, adequate sampling of the emitted seismicenergy is needed. This sampling may be accomplished by deploying one ormore fiber optic distributed vibration sensors in one or more boreholesthat are sufficiently close to the location of the microseismic event sothat the compressional and shear radiation patterns created by thegenerated fractures may be detected even in the presence of noise.

Referring now to FIG. 3, exemplary compressional and shear radiationpatterns 156 and 158 created by right lateral shear slippage of avertical fault 159 are shown. The pattern of at least some of the lobesof the radiation patterns 156, 158 may be detected, for instance, by thefiber optic distributed vibration sensors 150, 151, 155 and 159 that aredeployed in the monitoring boreholes 152 and 153 shown in FIG. 2. Inthis example, the fiber optic distributed sensors 150, 151, 155 and 159have a sufficient spatial resolution (e.g., approximately five meters)and frequency response (e.g., from approximately 5 Hz to 10 kHz) so asto provide for detection of the radiation pattern from at least some ofthe lobes of the pattern 161. In FIG. 2, the pattern 161 corresponds toa shear wave radiation pattern from an inclined fault 163 undergoingright lateral shear slip and the radiation pattern from two of the lobes160, 162 may be detected by distributed sensors 150, 151 deployed in theborehole 152. Although not shown, the radiation pattern from the otherlobes of the pattern 161 may be detected by the distributed sensors 155and 157 deployed in the borehole 153. In FIG. 2, the pattern 161 and theassociated ray paths 164 a-f of a portion of the seismic energy emittedfrom the hypocenter location 161 are shown superimposed on astratigraphic model of the formation 154 in the vicinity of theboreholes 152 and 153. In that model, line 166 a represents the boundaryof the formation 154, and lines 163, 167, 169, 171, 173, 175 and 177represent various faults/features in the formation 154. The ray paths164 a-f shown in FIG. 2 are shown as typical examples only, since thepaths are dependent on the seismic properties of the formation 154 whichaffect, for instance, the compressional and shear velocities and theattenuation of the radiated energy. These transmission effects may bequantified, either empirically or through modeling, so that theradiation patterns from the seismic waves detected by the fiber opticdistributed vibration sensors 150, 151, 155, 157 may be determined.

FIG. 4 illustrates an exemplary embodiment in which a fiber opticdistributed vibration sensor 170 is deployed in a borehole 172 and afiber optic distributed vibration sensor 171 is deployed in a borehole173, both of which extend into an earth formation 176 from a surface179. Distributed sensors 170 and 171 are configured to detect seismicsignals incident on the sensors 170 and 171 from outside the borehole172. The seismic signals 174 a-k in this example propagate through theformation 176 and are generated during a seismic survey using multipleseismic sources 178 a-b located at the surface 179. The distributedsensor 170 is coupled to an interrogation and data acquisition system200 that acquires and analyzes data from the sensor 170 to determinecharacteristic of the formation 176. Likewise, the distributed sensor171 is coupled to an interrogation and data acquisition system 201 thatacquires and analyzes data from the sensor 171.

Interrogation and data acquisition systems 200 and 201 may be separatesystems as shown or may be integrated into a single system with a singleoptical source that generates an optical signal that may be split forlaunching into the various sensors 170 and 171. In some embodiments, thesystems 200 and 201 (either separately or as an integrated system) mayacquire the data from the sensors 170 and 171 and then transmit theacquired data to a remote location for processing to determine variousparameters of interest, including parameters that are indicative of thecharacteristics of the formation 176 including (in some applications)the location and nature of microseismic events occurring in theformation 176. Data acquired from each of the distributed sensors 170and 171 may be synchronized to a common time source, such as a mastertiming trigger used to initiate interrogation of the sensors 170, 171 ora precision timing source (e.g., a GPS source), so that the data fromeach of the sensors 170, 171 may be correlated when processed.

FIG. 5 illustrates yet another exemplary embodiment in which fiber opticdistributed vibration sensors 180 and 182 are positioned atsubstantially different locations in the transverse cross-section of aborehole 184 that extends from surface 185 into a formation 186. Here,the sensors 180 and 182 are of identical construction so as to detectchanges in the phase of incident seismic signals 187 a-c and thusprovide for an estimation of their arrival direction. In thisembodiment, the seismic signals propagate through the formation 186 as aresult of a seismic source 194 (coupled to surface electronics 196)located in an adjacent borehole 198.

In any of the above embodiments or any other embodiment in which seismicor microseismic signals are detected using a fiber optic distributedsensor, one or more fiber optic distributed sensors may be deployed in aparticular borehole. In addition, one or more fiber optic distributedsensors may be deployed in each of a plurality of boreholes that are inthe vicinity of the seismic source. The data derived from the variousfiber optic distributed sensors (in the same borehole and/or in multipleboreholes) may be correlated as appropriate to enhance and/or provideadditional information regarding the seismic event and/or thecharacteristics of the earth formation.

In any of these exemplary embodiments, monitoring of the seismic signalsincident on the distributed fiber optic vibration sensor from outsidethe borehole may be based on coherent Rayleigh backscatter in which apulse of coherent light is launched into the optical fiber sensor andreturned light is analyzed. For incoherent illumination, the returnedlight as a function of elapsed time since the launching of the probepulse takes the form of a generally decaying waveform, the rate of decaybeing indicative of the loss in the optical fiber, with occasionallysmall features due to imperfections of the fiber, such as diametervariations or axial changes in the refractive index. However, withcoherent illumination, the backscatter waveform is additionallymodulated by a multi-path interference that occurs between the lightre-radiated by each scattering element. This modulation of the normallyslow backscatter signal is random (i.e., it depends on the relationshipbetween the optical source frequency and the spatial distribution of thescatterers in each elemental section of fiber), but stable. If the fiberis disturbed by a seismic wave, for example, the modulation of thebackscattered signal is varied in the vicinity of the disturbance. Suchvariations of the backscattered signal may be analyzed to detect eventsof a specified level and classified to determine the nature of thedisturbance. The coherent Rayleigh backscatter is sometimes referred toas “coherent Rayleigh noise” (CRN).

In some embodiments, rather than using a fully distributed fiber opticvibration sensor, an array of discrete reflectors or other sensors maybe inserted into the fiber 102. For instance, in one embodiment shown inFIG. 7, the reflectors may be fiber Bragg reflectors 220 a-c inscribedby side-illumination with a UV interference pattern. The fiber section222 a, 222 b between adjacent pairs of reflectors then becomes a lowreflectivity Fabry-Perot étalon and the fiber then comprises an array ofsuch étalons, forming an interferometric sensor array that can beinterrogated with a variety of methods known in the field of opticalfiber sensing. While the array approach is more costly than the fullydistributed one, the stronger reflectivity of the discrete reflectors,as compared for the Rayleigh backscatter, improves the signal-to-noiseratio and thus allows weaker acoustic signals to be detected. Therefore,which of these techniques is employed will depend on the particularapplication in which it is implemented and specifically on theanticipated acoustic signal strength as measured at the sensing opticalfiber 102. Although, the terminology “fiber optic distributed vibrationsensor” is used throughout this description, it is understood to alsoinclude arrays of fiber-optic vibration sensors.

FIG. 6 illustrates an exemplary embodiment of a data acquisition andinterrogation system 200 that may be used with a distributed fiber opticvibration sensor 202 for the CRN measurement. System 200 includes anoptical source 204 that generates an optical signal, such as an opticalpulse, for interrogating the fiber optic sensor 202, which is deployedin a borehole (not shown in FIG. 6). In some embodiments, the opticalsource 204 may comprise a narrowband laser (e.g., a fiber distributedfeedback laser) and a modulator that selects short pulses from theoutput of the laser. Optionally, an optical amplifier may be used toboost the peak power of the pulses. In some embodiments, this amplifiermay be placed after the modulator. The amplifier may also be followed bya filter for filtering in the frequency domain (by means of a band-passfilter) and/or in the time domain (by means of a further modulator).

The pulses emitted from the optical source 204 may be launched into theoptical fiber 202 through a directional coupler 206, which separatesoutgoing and returning signals and directs the latter to an opticalreceiver 208. The directional coupler 206 may be in bulk optic formusing a beamsplitter, or it may comprise a fiber-optic coupler, acirculator, or a fast switch (e.g. an electro-optic or acousto-opticswitch).

The backscattered optical signal returned from the sensing fiber 202 inresponse to the interrogating pulses may be detected and converted to anelectrical signal at the receiver 208. This electrical signal may beacquired by a signal acquisition module 210 (e.g., an analog to digitalconverter) and then transferred to a signal processing module 212 whichmay includes a processing device 214 (e.g., a microprocessor,microcontroller, digital signal processor, computer, etc.). In someembodiments, the signal processing module 212 analyzes the waveformsreceived to determine, at each location along the fiber 202, where thesignal is changing. In addition, the signal processing module 212 mayinterpret this change in terms of acoustic waves modulating thebackscatter return of the fiber 202. Code or instructions of softwarefor performing the analysis and interpretation may be stored in a memory216, which may include both durable and non-durable storage elements andmay further cooperate with the processing device 214 in executinginstructions of software

More specifically, the backscatter signal (including the CRN) producedin response to the interrogating pulses is directed to the opticalreceiver 208. At any given time T (i.e., corresponding to a particulardistance along the fiber 202), the electric field arriving at thereceiver 208 is the vector sum of all the electric fields generated byall the scatterers within the length of fiber 202 that was occupied bythe launched pulse at time T/2. The relative phase of these scatterers,dependent on the laser wavelength and distribution of the scatterers,determines whether the signals from these scatterers sum to a largeabsolute value (constructive interference) or essentially cancel eachother out (destructive interference).

In an exemplary embodiment, the receiver 208 includes a detector thatresponds to optical power (as opposed to an electric field) and thus hasa square-law response in terms of electric field. Thus, as the fiber 202is disturbed by the passing seismic waves, the optical fiber 202 isstrained by these waves if they couple to the fiber 202. A strain on thefiber 202 changes the relative position between the scattering centersby simple elongation of the fiber 202. The strain also changes therefractive index of the glass of the fiber 202. Both of these effectsalter the relative phase of the light scattered from each scatteringcenter. As a result, the interference signal in the disturbed region isvaried by modulation of the length of the optical fiber 202, since aninterference signal that may have been constructive (i.e., thescattering from each center was roughly in-phase, their electric fieldssum to a large value) is now destructive (i.e., the relative phase ofthe scattered signals from each reflector sum to a small electric fieldamplitude).

The foregoing description of the detection of the CRN signalsillustrates one embodiment in which the light from a single pulseundergoes direct detection. Other embodiments may launch optical pulsesat two or more frequencies, the scatter from which mix at the square-lawdetector in receiver 208 to yield a signal at a beat frequency orfrequencies. In yet other implementations, the backscatter may be passedthrough a compensating interferometer, which causes backscattered lightto interfere with the backscatter from another section of fiberseparated from the original backscattered light by a distance equal tohalf the path imbalance of the compensating interferometer;alternatively, the compensating interferometer may be placed in thelight path prior to the light being launched into the sensing fiber. Incases where compensating interferometers are used, the optical sourcecan be of relatively wide spectrum, since the compensatinginterferometer restores the mutual coherence of the optical signalsmixed at the detector. A further variant is the use of coherentdetection where the backscatter signal is mixed with a sample of thenarrowband optical source, usually referred to as the “localoscillator.” This coherent detection technique provides a low-noisemethod of detecting the signal since the signal reaching the detector isthe product of the electric fields of the local oscillator andbackscatter signals and the former may be selected to be sufficientlystrong so that the resulting mixed signal dominates the noise at thereceiver input.

Regardless of the particular technique implemented, the electricalsignals emerging from the receiver 208 may be processed to detect thepassage of the seismic wave and possibly to determine the relative timeof the wave's passage at different locations along the borehole, andpossibly the wave's spectral content. One way to achieve these resultsis to pass the signal to an analog-to-digital converter in the signalacquisition unit 210 and thereby digitize the receiver output for eachprobe pulse and with sufficient time resolution to be able to track theseismic wave. Signals from a set of probe pulses, but all correspondingto a single location along the borehole, may be combined into a singlewaveform that can be analyzed for spectral content, for example by meansof a Fourier transform. The time of arrival of the seismic signal may bedetermined by a number of estimation techniques, for example bydetermining the first moment of a signal corresponding to the deviationof the signal from its quasi-static mean value. The phase velocity maybe determined by comparing the time of pre-determined parts (for examplethe zero-crossing time) of the seismic waveform at successive locationsalong the borehole, or by extracting a phase estimate from the Fouriertransform and determining the partial derivative of phase versus theposition along the structure. The attenuation of various frequencycomponents may be determined, for example, by comparing acoustic spectraobtained at varying distances from the source of the seismic signal.

In embodiments in which data is acquired from multiple fiber opticdistributed sensors, each distributed sensor may be coupled to adedicated interrogation and data acquisition system (e.g., system 200).In other embodiment, multiple fiber optic distributed sensors may beinterrogated using a common optical pulse generator (e.g., a commonoptical source, modulator and amplifier) and the generated optical pulsemay then be split for launching into each of the individual fibers.

The embodiments of the invention may be directed to wells for productionof hydrocarbons, injection wells for improving hydrocarbon recovery,geothermal wells for energy extraction or storage, wells of CO₂sequestration and wells drilled for the specific purpose of seismicmonitoring. In addition, distributed fiber optic vibration sensors maybe deployed in multiple wells in the vicinity of a well containing aseismic source so that multiple simultaneous crosswell seismic surveysmay be conducted. Similarly, multiple nearby wells may be instrumentedwhile conducting almost any of the borehole seismic surveys discussedherein. Still further, multiple wells surrounding a well undergoinghydrofracturing stimulation may contain fiber optic vibration sensorsfor detecting seismic signals generated as a result of thehydrofracturing process.

While the invention has been disclosed with respect to a limited numberof embodiments, those skilled in the art, having the benefit of thisdisclosure, will appreciate numerous modifications and variationstherefrom. It is intended that the appended claims cover suchmodifications and variations as fall within the true spirit and scope ofthe invention.

1. A seismic event detection system, comprising: a first fiber opticcable disposed in a borehole extending from an earth surface into aformation, the first fiber optic cable configured to react along itslength to incident seismic signals originating outside the borehole andpropagating through the formation; an optical source to launch opticalpulses into the first fiber optic cable while the seismic signals areincident on the first fiber optic cable; and a data acquisition systemcoupled to the first fiber optic cable to detect coherent Rayleigh noise(CRN) generated in response to the optical pulses to determinecharacteristics of the formation based on the detected CRN.
 2. Thesystem as recited in claim 1, further comprising: a second fiber opticcable disposed in the borehole and coupled to the optical source, thesecond fiber optic cable configured to react along its length toincident seismic signals, wherein the first fiber optic cable isdisposed at a first location within a transverse cross-section of theborehole and the second fiber optic cable is disposed at a secondlocation within the transverse cross-section of the borehole that isspaced apart from the first location, and wherein the data acquisitionsystem detects a phase difference between seismic signals incident onthe first and second fiber optic cables at each of a plurality oflocations along a length of the borehole to determine characteristics ofthe formation.
 3. The system as recited in claim 1, further comprising:a second fiber optic cable disposed in a second borehole, the secondfiber optic cable configured to react along its length to incidentseismic signals originating outside the second borehole and propagatingthrough the formation; a second optical source to launch optical pulsesinto the second fiber optic cable while the seismic signals are incidenton the second fiber optic cable; and a data acquisition system coupledto the second fiber optic cable to detect CRN generated in response tothe optical pulses, wherein the CRN generated by the first fiber opticcable is correlated with the CRN generated by the second fiber opticcable to determine characteristics of the formation.
 4. The system asrecited in claim 1, wherein a hypocenter of a microseismic event isdetermined based on the detected CRN.
 5. The system as recited in claim1, wherein the first fiber optic cable comprises a plurality of discreteoptical sensors.
 6. The system as recited in claim 5, wherein thediscrete optical sensors comprise fiber Bragg gratings spaced apartalong the length of the first fiber optic cable.
 7. The system asrecited in claim 2, wherein the first fiber optic cable generates afirst CRN response to pressure, velocity, acceleration and/or strain andthe second fiber optic cable generates a second CRN response to the samepressure, velocity, acceleration and/or strain, and wherein the dataacquisition system determines characteristics of the formation based ona difference between the first CRN response and the second CRN response.8. The system as recited in claim 2, wherein the first and second fiberoptic cables are installed in a first control line.
 9. The system asrecited in claim 1, wherein the first fiber optic cable comprises apressure-sensitive material disposed along its length.
 10. A method ofdetecting seismic signals, comprising: deploying a first fiber opticcable in a borehole extending from a surface into an earth formation,the first fiber optic cable configured to react along its length toincident seismic signals; deploying a second fiber optic cable in aborehole extending from the surface into the earth formation, the secondfiber optic cable configured to react along its length to incidentseismic signals; launching optical pulses into the first and secondfiber optic cables during occurrence of a seismic event in the earthformation; and detecting backscattered optical signals generated by thefirst and second fiber optic cables in response to the optical pulses todetermine characteristics of the seismic event.
 11. The method asrecited in claim 10, wherein the second fiber optic cable is deployed inthe same borehole as the first fiber optic, the second fiber optic cablebeing disposed at a location within the transverse cross-section of thesame borehole that is spaced apart from a location of the first fiberoptic cable.
 12. The method as recited in claim 11, wherein detectingthe backscattered optical signals comprises detecting a phase differencebetween seismic signals incident on the first and second fiber opticcables.
 13. The method as recited in claim 10, wherein the detectingbackscattered optical signals comprises detecting coherent Rayleighnoise (CRN).
 14. A method for conducting a seismic survey of an earthformation, comprising: launching a first optical signal into a firstfiber optic cable disposed in a borehole extending from an earth surfaceinto the earth formation; generating a seismic wave that propagatesthrough the earth formation from outside of the borehole; and analyzingcoherent Rayleigh noise (CRN) produced in response to the first opticalsignal while the seismic wave is incident along a length of the firstfiber optic cable to determine characteristics of the earth formation.15. The method as recited in claim 14, further comprising: launching asecond optical signal into a second fiber optic cable disposed in aborehole; and analyzing CRN produced in response to the second opticalsignal while the seismic wave is incident along the length of the secondfiber optic cable, wherein characteristics of the earth formation aredetermined based on the CRN produced in response to the first opticalsignal and the CRN produced in response to the second optical signal.16. The method as recited in claim 15, wherein the first fiber opticcable and the second fiber optic cable have a substantially identicalconstruction and are disposed at different locations within a transversecross-section of the same borehole, and wherein characteristics of theearth formation are determined based on a phase difference in theseismic wave incident on the first and second fiber optic cables at eachof a plurality of locations along a length of the same borehole.
 17. Themethod as recited in claim 15, wherein the first fiber optic cable isconfigured to react differently to pressure, velocity, accelerationand/or strain than the second fiber optic cable reacts to pressure,velocity, acceleration and/or strain.
 18. The method as recited in claim14, further comprising providing a seismic source on the earth surfaceto generate the seismic wave.
 19. The method as recited in claim 14,further comprising deploying a seismic source in a second boreholeextending into the formation to generate the seismic wave.
 20. A systemcomprising: a first optical fiber disposed in a borehole that extendsfrom an earth surface into an earth formation, the first optical fiberconfigured to react to a seismic wave incident on the first opticalfiber at any of a plurality of locations along its length; a seismicsource to generate a seismic wave that originates outside of theborehole; an optical source to launch an optical signal into the firstoptical fiber to produce a backscattered optical signal while theseismic wave is incident on the first optical fiber; a receiver todetect coherent Rayleigh noise (CRN) in the backscattered signal; and aprocessing circuit to process the CRN to determine characteristics ofthe earth formation.
 21. The system as recited in claim 20, furthercomprising a second optical fiber disposed in a borehole extending fromthe earth surface into the earth formation and configured to produce asecond CRN signal while the seismic wave is incident at any of aplurality of locations along a length of the second optical fiber, andwherein the processing circuit further processes the second CRN signalto determine characteristics of the earth formation.
 22. The system asrecited in claim 21, wherein the first optical fiber and the secondoptical fiber are disposed in the same borehole.
 23. The system asrecited in claim 22, wherein the first optical fiber and the secondoptical fiber have a substantially identical construction and aredisposed at different locations within a transverse cross-section of thesame borehole, and wherein characteristics of the earth formation aredetermined based on a phase difference in the seismic wave incident onthe first and second fiber optic cables at each of a plurality oflocations along a length of the borehole.
 24. The system as recited inclaim 22, wherein the first optical fiber is configured to reactdifferently to pressure, velocity, acceleration and/or strain than thesecond optical fiber reacts to pressure, velocity, acceleration and/orstrain, and wherein characteristics of the earth formation aredetermined based on a difference in the reactions.
 25. The system asrecited in claim 20, wherein the seismic source is located on the earthsurface.
 26. The system as recited in claim 20, wherein the seismicsource is located in a second borehole that extends from the earthsurface into the earth formation, wherein the second borehole isdifferent than the borehole in which the first optical fiber isdisposed.
 27. The system as recited in claim 20, wherein the seismicsource is located in the earth formation.